Lengths of tubulars used to drill and complete bore holes in earth materials, referred to as joints, are typically joined by threaded connections to form a long assembly referred to as a drill string. Numerous threaded connection geometries are employed to provide sealing and load carrying capacities to meet drilling, installation and operating requirements. Of these geometries, connections having an external diameter greater than the pipe body are the most widely used. Thus the majority length of a typical drill string is comprised of alternating long lengths of generally cylindrical pipe separated by relatively short externally upset intervals at the connections.
Within the context of petroleum drilling and well completion, wells are typically constructed by drilling the well bore using one tubular string, largely comprised of drill pipe, then removing the drill pipe string and completing the well by installing a second tubular string, referred to as casing, which is subsequently permanently cemented in place. The tubular strings are formed by connecting joints of pipe with threaded connections. With this historic method of well construction, both the drill pipe and casing joint designs are separately optimized for the different performance requirements of the drilling and completion operations respectively. More specifically, the drill pipe connections must typically accommodate more torque to drill, than is required during completion, and must resist wear that occurs where the connection is in contact with the abrasive borehole wall during extended periods of drilling rotation. The tendency toward wear is strongly dependent on the lateral forces that arise at the points of contact between the drill string and borehole. These contact forces result from the interaction of several variables, but may be generally attributed to: inertia loads required to react the tendency of the rotating drill string to whirl, reaction of lateral load induced by the axial load transferred along the string through intervals of curvature and gravity loads in deviated intervals. Concentration of all or a majority of the wall contact load over the short upset interval containing the connection tends to exacerbate wear at these locations. This wear has the effect of generally reducing the diameter of the connections. For that reason, it is common industry practice to apply bands or zones of abrasion resistant coatings around the circumference of the drill pipe connections, referred to as hardbanding or hardfacing, to build up the diameter of the connection and thus provide a sacrificial layer of slow wearing material. U.S. Pat. Nos. 4,665,996 and 6,375,895 are two examples describing the materials and application methods used to apply such surface preparations to drill pipe tool joints.
Recent advances in drilling technology have enabled wells to be drilled and completed with a single casing string, eliminating the need to ‘trip’ the drill pipe in and out of the hole to service the bit and make room for the casing upon completion of drilling. This technology employs a wireline retrievable bottom hole drilling assembly capable of deployment on the distal end of casing strings. Development of the technology was initially motivated by potential cost savings arising from reduced drilling time and the expense of providing and maintaining the drill string, plus various technical advantages, such as reduced risk of well caving before installation of the casing. In addition to drilling, this technology finds utility in casing running applications where reaming is required to resize the borehole.
The established performance requirements for casing are only those required to meet the needs of historic well construction methods. The new use of casing to drill, naturally changes the performance requirements of the casing string. Such changes include increased torque capacity required to drill with the casing connections, but did not initially anticipate the need for increased wear resistance particularly in relatively straight wells where lateral forces arising from curvature and gravity are minimal. This expectation was based on the shorter exposure time to conditions of rotating wear likely for casing strings compared to drill pipe. (Drill pipe is used to drill many wells, resulting in extended exposure of drill pipe connections to conditions of rotating wear. In contrast, the application using a casing string to drill, deliberately only intends to expose the connections to rotating wear conditions for the time required to drill the single well interval to be cased by that string.)
However, it has been discovered that drilling with casing strings using industry standard threaded and coupled buttress (BTC) connections, having tapered pipe thread geometries specified by the American Petroleum Institute (API) and equipped with shoulder rings such as, for example, those described in Canadian Patent Application 2,311,156, frequently causes eccentric wear in the region of the connection. This wear may locally reduce the coupling side wall thickness until the coupling radius, in the region of wear, is little more than the pipe body. This amount of wear may occur during even a fraction of the relatively short period required to drill a single well interval in a nearly vertical well. As will be appreciated by one skilled in the art, this wear substantially compromises the load and sealing capacity of the connection.
This eccentric wear mechanism arises because the straightness of these connections are not as tightly controlled as in drill pipe, since the historic use of casing only contemplates the requirements of running, cementing and well access and not drilling. Thus a small bend in the string axis often occurs across the connections. Such bends tend to preferentially force the connections against the borehole wall at the ‘outside’ of the bends. The lateral wall contact force arising at these points of contact is strongly dependent on whether or not the lateral deflection imposed by the bend angles in the axially loaded casing is sufficient to interfere with the confining bore hole. This lateral interference acts to displace the casing string from its neutral position at the points of contact with the borehole, the casing string behaving as a long beam bent at the connections and restrained by the borehole. Particularly, where such lateral interference occurs between connections spaced one joint apart, the lateral load and hence wear rate is much greater than occurs over comparably ‘straight’ intervals.
For example, the connection bend angles were inferred a sample of typical 7 inch (178 mm) API buttress threaded and coupled (BTC) casing joints. These magnitudes were used to calculate the possible maximum lateral load arising from this load mechanism, were such casing joints assembled into a casing string and placed in a borehole drilled with a bit size of 8.5 inches (216 mm). It was found that, with negligible axial load, a lateral force of at least 1000 lbf (4450N) could be present if the casing string were so confined in an interval.
As described above, this lateral load mechanism is not normally present in drill pipe strings placed in a bore hole because the connections in those strings are typically straighter and the tube bodies flexurally less rigid than the same respective components of a casing string assembly. Furthermore, unlike the other lateral loading mechanisms which result in relatively axi-symmetric wear of the connection, wear resulting from the connection bend angle is non-axi-symmetric or eccentric.
This eccentric wear could be mitigated by providing connections with increased straightness. In certain applications this alternative may be preferable. However in general this will increase manufacturing cost and prevent the use of readily available tubulars. Furthermore, the presence of this new lateral wall contact load, while discovered to produce an unfavorable tendency toward excess wear, was simultaneously discovered to have a beneficial effect by improving borehole wall stability and reducing the risk of lost circulation when compared to drilling with straight drill pipe strings.
Excess wear can be avoided by use of a separate device, termed a wear band, as disclosed in Cdn. Patent App 2,353,249. The disclosed wear band includes a band of wear resistant material and is structurally attached to the casing adjacent the connection by crimping. This solution is effective and provides a readily implemented means enhance the usefulness of casing joints having standard non-wear resistant connections for casing drilling or reaming. However, the method requires additional handling and operations to crimp the wear bands to the casing joints with associated labour, capital and logistical overburden costs, plus introducing a longer upset interval length in the region of the connection, which longer interval must be accommodated by the pipe handling, running and drilling equipment.